Var management in an electric utility network of companies can be divided between the management of Var flows produced by the movement of bulk power within power network 90 (see FIG. 1b)) and the Var flow produced by utility customer inductive loads such as motors. The management of the Var flow created in these two ways is tightly coupled by the fundamental requirement that throughout the entire interconnected power system, inductive Var flow will at all times precisely equal capacitive Var flow.
In the power network 90 (see FIG. 1b)), Vars are produced by currents flowing through the inductance of transmission and sub-transmission lines within the power network. This Var flow is both measured and modeled mathematically in computers contained within a supervisory control and data acquisition system (SCADA) 92. The inductive Var flow is compensated by capacitor banks located at substations within the power network 90. Management of this Var flow is outside the scope of this invention.
Capacitors to compensate for Var flows generated by customer loads are compensated by capacitors mounted either within distribution substations 7 or along distribution lines 5. The following discussion is limited to the management of the compensation for customer generated Var flows.
In the operation of electric power distribution circuits, motor and other reactive loads, which build up during the day, cause a flow of reactive current 10 (measured in volt-amperes reactive or Vars, see FIGS. 6(a), (b), and (c). This reactive current increases line and transformer power losses. Reduction of this reactive power flow has at least three advantages for the electric utility:
1) Elimination of the cost of the power lost due to uncompensated customer generated Var flow. PA1 2) Prevention of the increase in temperature of equipment caused by uncompensated reactive power flow which otherwise decreases this equipment's life expectancy. PA1 3) Elimination of generation required to supply the losses thus reducing the need for new generation as loads increase. PA1 1) Inefficient operation of equipment whenever the voltage is above or below rated voltage. PA1 2) Shortened life of equipment due to high and low voltage variations. PA1 3) Increased cost of electricity resulting from poor control of Var flow by the electric utility. PA1 1) by time clocks, PA1 2) by controls that are sensitive to: PA1 3) by capacitor controls responding to radio or telephone line signals from a SCADA where use is made of a mathematical model of the power distribution system, sampled telemetering data and historical load data to estimate the need for switching capacitors.
Reactive currents taken by motors and other inductive loads lags the voltage by 90.degree.. The current taken by capacitors leads the voltage by 90.degree.. Synchronous generators are capable of accepting a current which is in phase with the leading current taken by capacitors. As a basic principle, the leading currents taken by capacitors and by generators balance the lagging currents taken by inductive loads. It is the vernacular of the industry to speak of capacitors or generators as `furnishing` Vars and inductive loads as `requiring` Vars. Hereinafter the term `providing leading Var flow` will be used as equivalent to the vernacular term `furnishing` Vars and the term `Var flow` used to indicate the presence of currents that may be leading or lagging. The term, `Var` is used as the magnitude of Var flow computed from products of reactive current and voltage.
Voltage drop along a distribution line is caused by load current flowing through the series resistance, R, and reactance, X, of the line. A useful term in calculating line losses and voltage drop is the ratio of reactance to resistance, X/R, generally referred to as the `X/R ratio`. The X/R ratio can be determined from the distribution line wire size and composition (copper or aluminum) together with the configuration and spacing of the power conductors and neutral or ground conductor, if used.
During the day increased current causes an undesirable voltage drop. This is often compensated for by raising the distribution substation output voltage giving nearby customers a higher than nominal voltage and distant customers a lower than nominal voltage. In order to maintain customer voltages within limits generally set by state regulation to +/-5%, on longer lines it may be necessary to use tapchanging regulators 11, see FIG. 6(a), at a point along a distribution line to further regulate the voltage. Such regulators make no improvement in inductive Var flow, and, in fact, add to the inductive Var flow due to their exciting current.
Consumer load devices operate most efficiently and have the longest life at rated voltage (generally 120 vac or a multiple thereof) and are adversely affected by variations in voltage. Customers therefore suffer in several ways with prior art technology, including:
To control the flow of reactive current as well as the voltage along distribution circuits, power factor capacitors are added at selected points along the lines radiating from distribution substations. Said capacitors may be connected from each of three phase lines to neutral, if on a three phase circuit, or from the single line to neutral of a single phase circuit. Said capacitors are generally mounted at the top of poles carrying the distribution circuits and are known as `pole-top capacitors`. Prior art practice is to switch some, but not all said pole-top capacitors.
Prior art pole-top capacitor switches are controlled in several ways:
a) voltage to neutral on a selected phase line, PA2 b) current in a selected phase line, PA2 c) outdoor temperature, and PA2 d) power factor or Vars, again using voltage and current from a selected phase line.
Each capacitor generally is connected and disconnected by means of a switch mechanism for each phase. It is the general prior art practice to switch all three capacitors on a three phase circuit with a single control.
When a bank is switched using a time clock, temperature or a voltage-sensitive control, a voltage transformer is required for a selected phase to provide operating power for the control. For voltage control the transformer furnishes information for measurement purposes. When switched using current, power factor or var control, both a voltage transformer and a current transformer or sensor are required for the selected phases.
Time clocks use historical data to determine capacitor switching operations and do not take into account actual daily variations in consumer load conditions and power line configurations. In addition, a long power outage may cause an error in the time setting, causing the capacitors to be connected at the wrong time of day. As a result, time clocks perform inadequately, but are widely used due to their relatively low cost.
Prior art voltage, power factor and var controls have fixed upper and lower voltage band-edges. These are the values of voltage that determine when to connect and disconnect the capacitor bank. The bandwidth is defined as the range within these two limits, where the measured voltage is said to be within limits, and no action is required of said control. These operating voltage points should not be confused with legal limits, often +/-5% of nominal voltage, as established by state statutes.
One problem with many prior art voltage responsive capacitor controls involves the change in voltage, B, that occurs when a capacitor bank is switched. This establishes an ideal bandwidth which however, being a function of the source impedance at the point of capacitor connection, tends in practice to be a variable. Any fixed control bandwidth must, therefore, be set above the highest expected voltage change, B, to prevent control instability.
Most distribution circuits are fed from one point at a time, however different substations can each feed a distribution line at two or more points. This permits the electric utility operators to change the feed to particular distribution circuits from one substation to another to balance loads on a substation, to maintain service to consumers during maintenance work, or to restore service when storms interrupt one of the feeder supplies. However, these changes can cause major differences in the source impedance at the capacitor location. Depending on the capacitor location, the source impedance, when fed from one substation, can vary by a factor of as much as five to one from that when fed from another substation. The resultant voltage change resulting from capacitor switching varies by the same ratio as the source impedance. Most prior art does not provide a way for a voltage sensitive capacitor control to automatically accommodate the requirement for a variable bandwidth.
Since the bandwidth cannot be accurately calculated, a common practice is to make the best estimate possible, then double the bandwidth. The result is a very crude correction of voltage and power factor, as compared to that desirable.
Power factor-sensitive or Var-sensitive controls are more costly than either a time clock or a voltage-sensitive control. U.S. Pat. No. 4,769,587 discusses a prior art power factor control in detail.
Many utilities have established a sophisticated mathematical model of the entire power system. The model operates using a network of computers located at generating stations, substations and a central control location. Each electric utilities computer system may communicate with neighboring systems forming a communications and computational system paralleling the power network 90. For greatest simplicity herein, this computational and communications network is referred to as SCADA 92 (see FIG. 1b)).
As explained above, one part of the mathematical model measures and controls the Var compensation of the Var flow generated by currents flowing in the power network of transmission and sub-transmission lines. In terms of the number of components and lines, the power network 90 is relatively simple as compared to the totality of distribution lines supplying customer power. It is the present practice to fully measure the power flows within the power network 90 and to control the switching of capacitor banks and control of static Var equipment. This transmission and sub-transmission system is well defined and not often changed. As a result the mathematical models are quite accurate.
Attempts are made to model distribution lines. The mathematical model selects capacitors along distribution lines for switching so as to establish minimum customer voltage variation and minimal distribution line losses. These customer related factors are not measured, however, but based on survey voltage studies of short duration and sometimes using real time inputs from a very small sampling of distribution voltage points. The apparent excellence of the results of the mathematical model may give a false sense of the actual real world quality of customer voltage variation and actual real world reduction of line losses.
Even if the mathematical model is without error for one distribution of customer load, this load distribution is continually changing and these changes are not monitored by the prior art systems. Moreover, there are long term changes in load pattern as new homes, commercial and industrial buildings are built. The burden of continually changing the mathematical model is expensive and time consuming and may not be kept up to date in actuality, especially at times of downsizing of utility manpower.
It is the prior art practice by many utilities to place a large portion of capacitors for customer load Var support at substations. One reason for this placement is the greater ease of remote control of capacitor switching of equipment at substations as compared to pole-top capacitor installations. Capacitors at substations are generally more expensive per kilovar of capacity, however, when located at substations.
Distribution circuit losses may be typically 6% of the generated power for a typical electric utility using prior art capacitor placement and control. Improved distribution line Var control could result in reduction of losses by 1%, say from 6% down to 5% The total power generated in the United States in one year may be 500.times.10.sup.9 kilowatt hours (kwh). At 8 cents per kwh a 1% reduction in losses represents an annual savings of $400 million.
Prior art distribution substations 7 (see FIG. 1(b) commonly use load tapchanging transformers (LTCT) 100, controlled by load tapchanger controls (LTC) 162 (see FIG. 2). An analog type of LTC is described in U.S. Pat. No. 3,721,894 issued to R. W. Beck with, the inventor thereof.
A digital LTC is described in U.S. Patent No. (U.S. patent application Ser. No. 08/152,001) filed Nov. 9, 1993 for Microcontroller-Based Tap-Changer Controller Employing Half-Wave Digitization Of A. C. Signals, filed in the name of Murty V. V. S. Yalla et al wherein R. W. Beckwith is named as one of the co-inventors.